Paraffin wax and asphaltene deposition costs the oil industry billions of dollars worldwide. Paraffin and asphaltene precipitation and deposition in crude oil transport flow-lines and pipelines is an increasing challenge for the development of deep-water subsea hydrocarbon reservoirs. When sufficiently deposited over time, paraffin wax and asphaltenes can partially or totally block oil production to uneconomical levels requiring shutdowns or various remediation treatments. Other problems caused by paraffin or asphaltene deposition include entrapment of produced water, which increases surface roughness on pipe walls leading to increased pumping pressure and reduced throughput, accumulations that fill process vessels and storage tanks, and interference with the operation of valves and other instrumentation. This deposition also occurs in producing wells where the paraffin and asphaltene deposits accumulate in and around the wellbore causing major restrictions. All of these problems may result in production shutdowns and hazardous conditions requiring extensive workovers, and resulting in production losses and possibly irreparable damage to equipment.
A plethora of thermal, chemical, and mechanical measures are available to manage these types of depositions on either a preventative basis (i.e., mitigation of deposition) or a remediate basis (i.e., removal of deposits). Typical deposition management systems include chemical inhibitors and the implementation of operations such as line heating, solvent circulation and, in shorter lines, mechanical scraping. But mechanical scraping processes (e.g., coiled tubing) are limited by their ability to only travel short distances, are costly, and involve significant risks. Additionally, solvents (e.g., xylene or toluene mixed with either diesel or kerosene) require heat to significantly increase paraffin and asphaltene solubility. The subsea temperatures dissipate the necessary heat quickly, rendering the solvents ineffective. This decreased efficiency of solvents results in the requirement for larger treatment volumes, longer treatment times, and ultimately a high cost. These solvents are also environmentally unfriendly.
It is commonly believed that paraffin wax is formed of molecules in the range of C20 and higher. However, due to pressure differences and very low temperatures inside and around subsea flow lines, these paraffin wax deposits begin to form with much smaller carbon chains. Since average subsea temperatures are below 40° F., paraffin compounds such as tridecane (C13, which freezes at 27° F.), tetradecane (C14, which freezes at 41.9° F.), pentadecane (C15, which freezes at 49.8° F.), and hexadecane (C16, which freezes at 64° F.) also begin to deposit on these flow lines as wax deposits. These paraffinic compounds all display only limited solubility at modest temperatures in many types of organic solvents and are virtually insoluble in aqueous solutions, although they can be re-melted between 120-150° F.
Asphaltene deposition is less driven by temperature and pressure. Instead, the deposition of asphaltenes is affected more by chemical changes in the crude oil. Asphaltene molecules are dispersed or floating in the crude oil. Lowering the pH of the system or introducing carbon dioxide or nonaromatic solvents can strip away the outer parts of the asphaltene molecules, which help to maintain dispersion of the asphaltene molecules. Without the outer parts, the asphaltene molecules will flocculate and precipitate.
Scale formation in natural gas pipelines may be attributed to a number of factors. Evaluation of scale samples indicate that the scale formations may include trace amounts of silica and clay from the formations from which the gas was derived, along with black powders and mineral scales. These scale formations may be very hard and may resemble sand stone. The use of monoethanol glycol (MEG) or methanol to retard the formation of natural gas hydrates has created the problem of decreased solubility of trace minerals. Additionally, basic agents (e.g., NaOH or NaHCO3) may be added to the MEG stream to increase pH for preventing corrosion. The increased pH, however, leads to decreased solubility of carbonate salts. Possible sources of the black powder include mill scale from the pipe manufacturing process, flash rust from hydraulic test water corrosion, and internal pipe corrosion. Chemical analyses of the black powder show that it consists mainly of a mixture of iron oxides and iron sulfides.